1. Field of the Invention
This invention relates to oxidative desulfurization and more particularly to a process for integrated deasphalting and oxidative removal of heteroatom-containing hydrocarbon compounds, such as organosulfur compounds, of liquid hydrocarbon feedstocks.
2. Description of Related Art
In conventional oil refinery operations, various processes occur in discrete units and/or steps. This is generally due to the complexity of naturally occurring whole crude oil mixtures, and the fact that crude oil feedstocks processed at refineries often differ based on the location and age of the production well, pre-processing activities at the production well, and the means used to transport the crude oil from the well to the refinery plant. Two very important and conventionally separate preliminary refining processes include removal of heteroatom-containing hydrocarbon compounds, such as desulfurization to reduce the organosulfur compounds present, and solvent deasphalting to separate the relatively heavy asphaltenic materials from a lighter deasphalted and demetalized phase. The deasphalted/demetalized phase is further refined into various petroleum products including transportation fuels.
Whole crude oil commonly contains organosulfur compounds and heteroatom compounds such as those containing nitrogen. These compounds are generally undesirable and must be removed at one or more stages during refinery operations. Light crude oil has a sulfur content as low as 0.01 weight %. In contrast, heavy crude oil can contain up to about 3 weight % sulfur. Similarly, the nitrogen content of crude oil is in the range of 0.001-1.0 weight %. The heteroatom and carbon residue (measured as Ramsbottom carbon residue, or RCR) content of various Saudi Arabian crude oils are given in Table 1, where “ASL” refers to Arab Super Light, “AEL” refers to Arab Extra Light, “AL” refers to Arab Light, “AM” refers to Arab Medium and “AH” refers to Arab Heavy.
TABLE 1PropertyASLAELALAMAHGravity, °51.439.533.031.127.6Sulfur, W %0.051.071.832.422.94Nitrogen, ppmw70446106414171651RCR, W %0.511.723.875.277.62Ni + V, ppmw<0.12.92134.067
The heteroatom content of crude oil generally increases with decreasing API gravity, or increasing heaviness, as is apparent from Table 1. The heteroatom content of crude oil fractions also increases in higher boiling fractions, as shown in Table 2:
TABLE 2Fractions, ° C.Sulfur WT %Nitrogen ppmwC5-90 0.01— 93-1600.03—160-2040.06—204-2600.34—260-3151.11—315-3702.00253370-4302.06412430-4822.65848482-5703.091337 
In a typical refinery, crude oil is first fractionated in an atmospheric distillation column to separate tops including sour gas, e.g., hydrogen sulfide, and light hydrocarbons such as methane, ethane, propane, and butanes. Naphtha (36-180° C.), kerosene (180-240° C.), and gas oil (240-370° C.) are typically recovered as sidestreams from the distillation column. Atmospheric residue, which is the hydrocarbon fractions boiling above 370° C., is discharged as bottoms. The atmospheric residue from the atmospheric distillation column is either used as fuel oil or sent to a vacuum distillation unit, depending on the configuration of the refinery. Main products from the vacuum distillation unit include vacuum gas oil, having hydrocarbons boiling in the range of 370-520° C., and vacuum residue, encompassing hydrocarbons boiling above 520° C.
As the boiling point of the petroleum fractions increases, the quality of oil decreases and thus negatively impacts the downstream processing units. Tables 3 provide quality of atmospheric residue (boiling above 370° C.) and Table 4 provides quality of vacuum residue (boiling above 520° C.) derived from various crude sources:
TABLE 3API Gravity,Sulfur,Ni + V,CCR,SourceName°W %ppmwW %Middle EastArabian Light16.803.14550.007.60Middle EastArabian Heavy12.704.30125.0013.20South AsiaMunis26.400.1516.004.20South AsiaDuri17.500.2217.009.30ChinaShengli18.701.2319.008.60ChinaTaching25.100.134.004.00Latin AmericaMaya8.304.82494.0017.40Latin AmericaIthmus13.902.9653.008.20North AmericaCold Lake6.685.05325.0018.30
TABLE 4API Gravity,Sulfur,Ni + V,CCR,SourceName°W %ppmwW %Middle EastArabian Light6.904.34141.0020.30Middle EastArabian Heavy3.006.00269.0027.70South AsiaMunis17.300.1944.0010.40South AsiaDuri13.000.2532.0015.20ChinaShengli11.701.6628.0016.40ChinaTaching18.700.189.009.50Latin AmericaMaya−0.105.98835.0029.60Latin AmericaIthmus4.004.09143.0021.10Middle EastKirkuk11.715.14189.0018.20
Tables 3 and 4 clearly indicate that the atmospheric or vacuum residues are highly contaminated with heteroatoms and have high Conradson carbon residue (CCR) content. In addition, Tables 3 and 4 show that the quality of the hydrocarbon deteriorates with increasing boiling point.
Naphtha, kerosene and gas oil streams from crude oils or other natural sources such as shale oils, bitumens and tar sands, are conventionally treated to remove contaminants, mainly sulfur, the quantity of which exceeds the allowable specifications. Hydrotreating is the most common technology to remove these contaminants. Vacuum gas oil is processed in a hydrocracking unit to produce gasoline and diesel or in a fluid catalytic cracking unit to produce mainly gasoline, light cycle oil (LCO) and heavy cycle oil (HCO) as by-products. LCO is typically either used as a blending component in a diesel pool or fuel oil, and HCO is generally sent directly to a fuel oil pool. There are several processing options for the vacuum residue fraction, including hydroprocessing, coking, visbreaking, gasification and solvent deasphalting.
Contaminants such as sulfur, nitrogen, and poly-nuclear aromatics in the crude oil fractions impact the downstream processes including hydrotreating, hydrocracking and FCC. The contaminants are present in the crude oil fractions in varying structures and concentrations.
Solvent deasphalting processes are well know art and practiced worldwide. Solvent deasphalting is a separation process in which residue is separated by solubility, instead of by boiling point as in vacuum distillation processes. In general, solvent deasphalting processes produce a low-contaminant deasphalted oil (DAO) rich in paraffinic type molecules. These fractions can then be further processed in conventional conversion units such as an FCC unit or a hydrocracking unit. Solvent deasphalting is usually carried out with paraffin streams having a carbon number ranging from 3-7, preferably 4-5, at or below the critical conditions of the solvent. Table 5 lists key properties of common solvents used in solvent deasphalting.
TABLE 5MWBoilingCriticalCritical(g/g-PointSpecificTemperaturePressureNameFormulamol)(° C.)Gravity(° C.)(bar)propaneC3H844.1−42.10.50896.842.5n-butaneC4H1058.1−0.50.585152.137.9i--butaneC4H1058.1−11.70.563135.036.5n-pentaneC5H1272.236.10.631196.733.8i--pentaneC5H1272.227.90.625187.333.8
The feed is mixed with the solvent so that the deasphalted oil is solubilized in the solvent. The insoluble pitch precipitates out of the mixed solution. Separation of the DAO phase (solvent-DAO mixture) and the pitch phase typically occurs in an extractor designed to efficiently separate the two phases and minimize contaminant entrainment in the DAO phase.
The DAO phase is then heated to conditions at which the solvent becomes supercritical. Under these conditions, the separation of the solvent and DAO is relatively easy in a DAO separator. Any entrained solvent in the DAO phase and the pitch phase is stripped out, typically with a low pressure steam stripping apparatus. Recovered solvent is condensed and combined with solvent recovered under high pressure from the DAO separator. The solvent is then recycled back to be mixed with the feed.
Solvent deasphalting is carried-out in liquid phase thus the temperature and pressure are set accordingly. There are generally two stages for phase separation in solvent deasphalting. In a first separation stage, the temperature is maintained at a lower level than the temperature in the second stage to separate the bulk of the asphaltenes. The second stage temperature is carefully selected to control the final deasphalted/demetalized oil quality and quantity. Excessive temperature levels will result in a decrease in deasphalted/demetalized oil yield, but the deasphalted/demetalized oil will be lighter, less viscous, and contain less metals, asphaltenes, sulfur, and nitrogen. Insufficient temperature levels has the opposite effect such that the deasphalted/demetalized yield decreases but the product quality is higher.
Operating conditions for solvent deasphalting units are generally based on a specific solvent and charge stock to produce a deasphalted/demetalized oil of a specified yield and quality. Therefore, the extraction temperature is essentially fixed for a given solvent, and only small adjustments are typically made to maintain the deasphalted/demetalized oil quality. Large variations in temperature should be avoided as the resulting solubility change can severely upset the operation. This is especially true at temperatures near the critical temperature of the solvent in which solubility is more sensitive to temperature.
The composition of the solvent is also an important process variable. The solubility of the solvent increases with increasing critical temperature, such that C3<iC4<nC4<iC5, i.e., the solubility of iC5 is greater than that of nC4, which is greater than that of iC4, is greater than that of C3. An increase in critical temperature of the solvent increases the deasphalted/demetalized oil yield. However, solvents having higher critical temperatures afford less selectivity resulting in lower deasphalted/demetalized oil quality.
Solvent deasphalting units are operated at pressures that are high enough to maintain the solvent in the liquid phase, and is not considered a process variable and thus should not be changed unless changes are made on the solvent composition.
The volumetric ratio of the solvent to the solvent deasphalting unit charge is also important in its impact on selectivity, and to a lesser degree, on the deasphalted/demetalized oil yield. The major effect of the solvent-to-oil ratio is that a higher ratio results in a higher quality of the deasphalted/demetalized oil for a fixed deasphalted/demetalized yield. A high solvent-to-oil ratio is preferred because of better selectivity, but increased operating costs conventionally dictate that ratios be limited to a relatively narrow range. Selection of the solvent is also a factor in establishing operational solvent-to-oil ratios. The necessary solvent-to-oil ratio decreases as the critical solvent temperature increases. The solvent-to-oil ratio is, therefore, a function of desired selectivity, operation costs and solvent selection.
It is difficult to generalize the impact of feed composition because of the many variables involved. The API, the characterization factor (known as the “k” factor established by UOP, LLC of Des Plaines, Ill., USA), the asphaltenes content, the Conradson carbon content, the metals content, the nitrogen content, and the sulfur content all influence the quantity and quality of deasphalted/demetalized oil produced. In general, heavier feed results in lower quality of deasphalted/demetalized oil for a given deasphalted/demetalized oil yield. The feed composition is expected to be within a specified design range, and any small changes in feed composition can be compensated for by variation in the extraction temperature. Major changes in feed, such as use of crude of a different type or from a different source, typically require variations in operating conditions and/or different solvent selection.
The pitch product contains a majority of the contaminants from the charge, i.e., metals, asphaltenes, Conradson carbon, and is also rich in aromatic compounds. A three-product unit, in which resin, DAO and pitch can be recovered, is also available. This design allows for a range of bitumens to be manufactured from various resin/pitch blends.
Additional description related to solvent deasphalting units is well know, for instance, as described in U.S. Pat. Nos. 4,816,140, 4,810,367, 4,747,936, 4,572,781, 4,502,944, 4,411,790, 4,239,616, 4,305,814, 4,290,880, 4,482,453, and 4,663,028, all of which are incorporated by reference herein.
As mentioned above, sulfur is a contaminant that must be substantially removed at some point in the refinery operation. The discharge into the atmosphere of sulfur compounds during processing and end-use of the petroleum products derived from sulfur-containing sour crude oil pose health and environmental problems. Stringent reduced-sulfur specifications applicable to transportation and other fuel products have impacted the refining industry, and it is necessary for refiners to make capital investments to greatly reduce the sulfur content in gas oils to 10 parts per million by weight (ppmw) or less. In the industrialized nations such as the United States, Japan and the countries of the European Union, transportation fuel refineries have already been required to produce an environmentally clean product. For instance, in 2007 the United States Environmental Protection Agency required the sulfur content of highway diesel fuel to be reduced 97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels sold in 2009 to contain less than 10 ppmw of sulfur. Other countries are following in the footsteps of the United States and the European Union and are moving forward with regulations that will require refineries to produce transportation fuels with an ultra-low sulfur level.
Accordingly, impurities such as sulfur, nitrogen and other heteroatoms must be removed prior to or during refining to meet the environmental regulations for the final products (e.g., gasoline, diesel, fuel oil) or for the intermediate refining streams that are to be further upgraded, such by reforming isomerization.
To keep pace with recent trends toward production of ultra-low sulfur fuels, refiners must choose among processes or crude oil sources that ensure future specifications are met with minimum additional capital investment, in many instances by utilizing existing equipment. Conventional technologies such as hydrocracking and two-stage hydrotreating offer solutions to refiners for the production of clean transportation fuels. These technologies are available and can be applied as new grassroots production facilities are constructed. However, many existing hydroprocessing facilities, such as those using relatively low pressure hydrotreaters, represent a substantial prior investment and were constructed before these more stringent sulfur reduction requirements were enacted. It is very difficult to upgrade existing hydrotreating reactors in these facilities because of the comparatively more severe operational requirements (i.e., higher temperature and pressure) to obtain clean fuel production. Available retrofitting options for refiners include elevation of the hydrogen partial pressure by increasing the recycle gas quality, utilization of more active catalyst compositions, installation of improved reactor components to enhance liquid-solid contact, increasing of reactor volume, and increasing the feedstock quality.
Refractory sulfur compounds, which are considered very difficult to remove in hydrotreating processes conventionally employed for desulfurizing crude oil, include condensed-ring sulfur-bearing heterocyclic dibenzothiophene, shown below:
In addition, certain substituted dibenzothiophenes are particularly difficult to remove. A refractory sulfur compound, which is considered the most difficult to remove in processes employed for desulfurizing crude oil, include condensed-ring sulfur-bearing heterocyclic 4,6-dimethyldibenzothiophene, shown below:
4,6-dimethyldibenzothiophene can account for a significant percentage of the total organic sulfur in hydrocarbon mixtures such as whole crude oil. This compound can account for as much as 90 ppmw of the total sulfur content of Arabian Light crude oil, as much as 110 ppmw of the total sulfur content of Arabian Medium crude oil, and as much as 108 ppmw of the total sulfur content of Arabian Heavy crude oil. Although these concentrations are relatively low, 4,6-dimethyldibenzothiophene is very difficult to remove during the hydrotreating process at mild hydrotreating conditions, e.g., 30 Kg/cm2 pressure.
Oxidative desulfurization using liquid oxidizing agents in the presence of a catalyst, or combination of catalysts, is known to desulfurize dibenzothiophene and various substituted dibenzothiophenes including 4,6-dimethyldibenzothiophene, as well as other organosulfur compounds including, but not limited to, mercaptans and thiophenes. Organosulfur compounds and, in certain processes, organonitrogen compounds, are oxidized, and oxidation products are subsequently removed from the hydrocarbon product by extraction or other means. Oxidative desulfurization is described, for instance, in U.S. Pat. Nos. 3,278,562, 3,551,328, 3,719,589, 6,160,193, 6,171,478, 6,274,785, 6,277,271, 6,402,940, 6,406,616, 6,596,914, US Patent Publications US20070151901, US20060131214 US20020035306, US20030094400 and US20040178122; PCT Publications WO2007103440, WO2007106943, WO2006071793, WO2005012458, WO2003014266; and European Patent Publication EP1674158; all of which are incorporated by reference herein.
In Herbstman, et al. U.S. Pat. No. 3,719,589, a process is disclosed in which oil containing sulfur and asphalt is subjected to oxidation with organic peroxides or organic peracids. In this process, the sulfur- and asphalt-containing oil mixture (without solvent) is heated to promote phase separation. Notably, this process does not comprehend the use of solvent as in known solvent deasphalting processes, and temperature conditions generally above the critical temperatures of solvents used in known solvent deasphalting processes must be used to effectuate thermal phase separation.
It is desirable to remove at least some portion of the contaminants, including sulfur and nitrogen, during early processing steps in the refinery. Also, as discussed above, it is often necessary to deasphalt the crude oil during refinery operations in order to fraction the crude oil into useful products and maximize recovery of valuable products. However, conventional pretreatment desulfurization and deasphalting of crude oil generally requires separate and distinct process steps and associated unit operations equipment. For instance, in most refineries, desulfurization is performed on the various fractions following distillation, and heavy distillation products are separately deasphalted.
Accordingly, a need exists for an efficient and effective method for desulfurization and deasphalting of hydrocarbons, such as crude oil or bottoms from various refinery processes. As petroleum companies look to economize in light of increased processing costs, as well as more stringent worldwide regulations regarding sulfur content of transportation fuels, this need becomes more urgent. The elimination or minimization of equipment presently used for desulfurization and deasphalting, or consolidation of the existing equipment, to increase efficiency and lower costs, would be desirable.
Therefore, it is an object of the present invention to provide an integrated desulfurization and deasphalting process that can be practiced without substantial addition to existing facilities of costly equipment, hardware and control systems.